NGL Energy Partners LP announced that it has signed an agreement with SemStream L.P., a subsidiary of SemGroup Corporation, whereby SemStream will contribute substantially all of its natural gas liquids business and assets to NGL for common units and cash. In addition, SemStream will acquire an interest in the general partner of NGL. SemStream will have the right to appoint two members to the board of directors of the general partner.

Stephen Tuttle, President of the Midstream Division, stated, "This transaction will increase the number of terminals owned by the Partnership from three to fifteen, significantly expanding our midstream segment from the Mid-Continent to the West Coast, including Washington and Arizona. These assets generate fee-based revenues and complement our current wholesale supply and marketing business. In addition, we welcome all of the current SemStream employees to the NGL family and believe the combined teams will provide one of the strongest platforms for delivering NGLs in today's marketplace."

At closing, NGL will issue approximately 8,950,000 common units to SemStream for the assets. In addition, up to a maximum of $100 million in cash will be paid in connection with working capital acquired. The cash working capital payment will be financed from borrowings under NGL's amended revolving credit facility. The transaction is subject to clearance under the Hart-Scott-Rodino Antitrust Improvements Act and other customary closing conditions and is expected to close in the fourth quarter of 2011. NGL expects this transaction to be accretive to its unitholders.

Brian Pauling, Chief Operating Officer of the Midstream Division, said, "These assets and operations will provide balance between our business segments and continue the geographic expansion of our operation. This will position NGL to take advantage of opportunities arising from the expanding liquids rich shale plays throughout North America."

The assets include 12 natural gas liquids terminals, located in Arizona, Arkansas, Indiana, Minnesota, Missouri, Montana, Washington and Wisconsin, with over 12 million gallons of above ground propane storage, approximately 3.7 million barrels of underground leased storage for natural gas liquids, and a rail fleet of approximately 350 leased and 12 owned cars.

U.S.

Mariner West Open Season Successful for Sunoco Logistics

Sunoco Logistics Partners L.P. announced on September 7, that it had a successful open season for Project Mariner West. Sunoco Logistics received binding commitments that enable the project to proceed as designed with an initial capacity to transport approximately 50,000 barrels per day and the ability to expand to support higher volumes as needed.

Mariner West is a pipeline project developed jointly by Sunoco Logistics and MarkWest Liberty Midstream & Resources, LLC, a partnership between MarkWest Energy Partners, L.P. and The Energy & Minerals Group. The project will deliver ethane from the liquid-rich Marcellus Shale processing and fractionation areas in Western Pennsylvania to the Sarnia, Ontario petrochemical market.

Together with Mariner East, a previously announced Sunoco Logistics/MarkWest Liberty pipeline and marine project developed to transport ethane produced in the Marcellus to the U.S. Gulf Coast and International markets, these projects provide Marcellus producers with a comprehensive ethane takeaway solution for the Marcellus Shale basin.

"We are pleased to announce a successful open season for Mariner West," said Lynn L. Elsenhans, chairman and chief executive officer. "We received binding commitments that enable this project to move forward. The project is underway and is scheduled to be operational by July 2013. In addition, we look forward to continuing to work on the Mariner East project and expand our relationship with MarkWest Liberty. We believe our existing infrastructure and the ability to reach multiple market destinations provide a cost-efficient and flexible solution to transport additional Marcellus Shale ethane production."

NuStar, Valero Plan South Texas Pipeline Projects to Three Rivers and Corpus Christie Refineries

NuStar Energy L.P. announced September 7 that the company has entered into an agreement with Valero Energy Corporation in which NuStar will modify existing sections within its South Texas pipeline system and build new sections to transport Eagle Ford and other crude oils. These projects will help Valero improve transportation of crude and condensate to supply its refineries in Three Rivers, Texas and Corpus Christi, Texas.

NuStar will reverse an eight-inch refined products pipeline that currently runs from Corpus Christi to Three Rivers and will convert it to crude oil service. The pipeline will provide capacity to transport Eagle Ford crude and condensate to Valero's Corpus Christi refinery, and the line is expected to be in full service by the end of September 2011.

NuStar will also build 55 miles of new 12-inch pipeline that will connect to existing pipeline segments to move crude oil from Corpus Christi to Valero's Three Rivers refinery. This system is expected to be completed and in service by the second quarter of 2012.

"These projects are an important part of our ongoing strategy to increase our customers' ability to move crude in South Texas," said Curt Anastasio, president and CEO of NuStar. "With the growing production from the Eagle Ford region, NuStar is in the unique position to provide Valero and our other customers with quick transportation solutions given the fact that we have hundreds of miles of existing pipeline running from that region into Corpus Christi, where it can be refined or transported to other locations."

Vaalco Energy Finalizes $5 Mln Bakken Farm-in Deal with Magellan Petroleum

U.S. independent Vaalco Energy has finalized a farm-in deal with Magellan Petroleum for the deep rights to about 23,000 acres in the Bakken oil play in Roosevelt County, Montana.

Vaalco said it had paid Magellan $5 million for a 65% working interest in the Poplar field.

Under the terms of the deal, which was first announced in July, Vaalco will drill three wells at a combined cost of about $15 million.

One of the wells will be drilled horizontally to test the Bakken formation. That well is the main thrust of this deal, Vaalco chief executive Bob Gerry told Upstream.

“That’s the big one,” he said.

Vaalco will also drill a vertical well targeting the Red River formation.

Gerry could not say which of these wells would be drilled first and that the third well’s target would be determined after gathering more information.

All wells will be drilled by the end of next year, with the first planned to spud by 1 June.

Vaalco, which has its primary operations off West Africa but has been diversifying in oily onshore plays, bought a 70% working interest from a private company in about 5200 Bakken acres in the Flat Lake field in Sheridan County, Montana.

Gerry said Vaalco is still assessing seismic data and looking for rigs to drill that acreage.

He said the company would likely be able to drill in the Poplar field before it was ready to spud a Flat Lake well.

“Wherever we can find the rig, we’ll drill it first,” he said.

Pennsylvania Court Ruling Casts Shale Gas Leases in Doubt

A Pennsylvania court ruling has raised questions about the validity of billions of dollars in leases bought by oil and gas companies to access the vast Marcellus shale natural gas resource in Pennsylvania.

The state Superior Court has ruled that a lower court should obtain expert opinions as to whether the right to capitalize on shale gas belongs to the owner of the gas rights or the mineral rights.

“It has the potential to be huge,” said James Pellow, a leasing attorney for Eckert Seamans in Pennsylvania. “Gas operators stand to lose enormous sums of money if the courts decide they do not have title to the oil and gas under their leases.”

In Pennsylvania, there are considered three different rights for sale underground – rights to the minerals, such as limestone; rights to coal; and rights to oil and gas.

Shale gas had never come into question because the technology to economically extract it had not been put in place until the past few years. While the oil and gas industry started in Pennsylvania, most of the prime fields were deemed to have been tapped out, with production over the past 40 years marginal.

However, within the past five years, the discovery that multi-staged hydraulic fracking combined with horizontal drilling could economically extract gas from tight shale rock opened Marcellus as the biggest gas field in the U.S. and companies such as Chesapeake and Anadarko rushed to become involved.

“Once the rush is on to lease up acreage, sometimes people go faster than they should,” said Larry Nettles, an attorney with Vinson & Elkins, which focuses on the oil and gas industry.

Mr Pellow added that while many gas companies believed leasing drilling rights from owners of gas rights made sense, uncertainty about how this will play out goes back to the 1980s when the Pennsylvania Supreme Court said the owner of coal rights had the right to profit from coal bed methane because the methane gas could only be obtained by accessing the coal. In other words, the owner of gas rights could not profit from the gas produced.

“Coal was king in Pennsylvania,” Mr Pellow said. “So you understand why that decision came out that way even though it is difficult to reconcile with existing legal precedents.”

Many landowners had decades ago leased gas rights to independent drillers in Pennsylvania for hundreds of dollars an acre or less. But when the rush into the Marcellus began, Mr Pellow said lawyers thought they could get landowners in on the bonus payments of up to $5,000 an acre paid by drillers if they could claim that because the gas was trapped in the shale minerals, the owner of the shale rights owned the gas.

“Determining mineral ownership may sound easy but it can get quite complex, particularly in a place such as Appalachia where landholdings have been subdivided for many generations,’’ said Raoul LeBlanc, senior director at PFC Energy, the consultancy.

“But companies must go to the trouble because, without a valid lease, no one can do anything securely. As they say in oil companies: ‘No lease, no grease.’”

The industry is continuing to produce gas while the courts study the matter.

“There is a lot at stake,” Mr Pellow said. “If the final ruling is against the industry, this will go to the Pennsylvania Supreme Court.”

Exxon Mobil Acquires Drilling Leases in Ohio Utica Shale Area

Exxon Mobil Corp. said September 22 it has acquired leases in Ohio's Utica Shale, marking its first foray into a field that is thought to hold vast amounts of crude oil.

Exxon spokesman Jeff Neu said the company is "active" in the Utica Shale. He was responding to questions about a report from a publication in Wheeling, W.Va., that said scores of land owners have signed leases with the oil giant this month.

The Wheeling News-Register in West Virginia reported September 17 that leases were signed for $4,950 per acre and 19% on production royalties. Exxon Mobil, the world's largest public oil company, confirmed it has signed the leases but declined to comment on the price it is paying per acre or the percentage on production royalties. The company didn't disclose the size of its position.

Several oil and gas companies, including Anadarko Petroleum Corp., Hess Corp., Devon Energy Corp. and Chesapeake Energy Corp. have rushed to secure leases in an area that many believe is the latest big North American onshore oil discovery.

The Utica, a deeply buried rock formation, lies below parts of eight states, from Tennessee to New York, as well as parts of Canada. Oil companies, however, have concentrated their leasing and exploration efforts in eastern Ohio, which they believe will yield more valuable oil and natural gas.

This month, Hess said it spent more than $1.34 billion acquiring 185,000 acres in Ohio. The New York-based company spent $593 million on a 50% stake in 200,000 acres held by Consol Energy Inc. and spent another $750 million acquiring closely held Marquette Exploration LLC, which had 85,000 acres in the shale.

Ohio's Utica Shale is a neighbor of Pennsylvania's Marcellus Shale, where Exxon acquired a large presence after its purchase last year of natural-gas company XTO Energy.

Enbridge Revises Upward to $700 Mln Cleanup Cost of Michigan Oil Spill

Enbridge Energy Partners revised upward the estimated cleanup cost of the oil spill in southern Michigan in its latest filings with the federal government.

Line 6B of the Lakehead oil pipeline ruptured in July 2010 near Marshall, Mich. The EPA estimated more than 23,000 barrels of heavy oil from Alberta tar sands spilled from the pipeline into the Kalamazoo River and nearby Talmadge Creek.

The energy company initially estimated the cost of the cleanup and potential claims at $430 million, then later to $585 million. In its latest filing with the Securities and Exchange Commission, the company said it expects the cost to be $700 million, WOOD TV 8 in Grand Rapids, MI, reported.

The U.S. Environmental Protection Agency said it spent more than $29 million cleaning up the spill.

The EPA recovered about 18,000 barrels of oil from the surface. Officials said it was unclear how the remaining oil would affect the environment because there is no spill with which to compare the Enbridge leak.

The nature of oil from tar sand deposits causes some of it to sink to the river bottom where it soaked about 6 inches of sediment.

The EPA set an August 31 deadline for Enbridge to remediate parts of southern Michigan affected by an oil spill in July 2010. Enbridge spokeswoman Lorraine Grymala said earlier this month the EPA set the deadline before the extent of the spill was reviewed this summer.

Enbridge Suffers First Operating Loss in Five Years after 2010 Spills

Canadian pipeline company Enbridge spent more than $500 million cleaning up a summer oil spill in southern Michigan, company data show.

Line 6B of the Lakehead oil pipeline system ruptured in late July near Marshall, Mich., dumping around 20,000 barrels of oil into the Talmadge Creek and Kalamazoo River.

Enbridge in its annual report said it spent $550 million on the July spill, excluding insurance costs, fines and penalties.

The company spent another $45 million related to a similar accident in September in Illinois. Line 6A of the Lakehead pipeline network near Romeoville, IL; spilled oil onto a roadway and into a nearby retention pond on September 9, 2010.

Repairs and cleanup costs wound up contributing to the company's first operating loss in at least five years.

U.S. Transportation Department Secretary Ray LaHood said his agency adopted a plan to make sure operators know the age and condition of their pipelines. Additional regulations would strengthen inspection requirements and provide more public access to safety records.

Pipeline operators could face penalties of as much as $2.5 million for a string of violations.

Osum Selects Veolia Produced SAGD Water Treatment for Alberta Taiga Project at Cold Lake

Osum Oil Sands Corp. will use water treatment technologies from Veolia Water Solutions & Technologies to process produced water from its Taiga Project at Cold Lake in Alberta. Osum will produce bitumen utilizing the in-situ, Steam Assisted Gravity Drainage (SAGD) process beginning production in 2013.

This produced water treatment system consists of AutoFlot(R) Induced Gas Flotation (IGF) and Power Clean(R) Oil Removal Filter (ORF) technologies for the secondary deoiling process. HPD evaporators will then process the de-oiled produced water to provide high-quality water to the Once-Through Steam Generators (OTSG) as well as treat the resulting blowdown.

The produced water treatment system is an example of the adoption of technologies and directives by Osum to minimize the impact of the Taiga Project on the surrounding environment. The evaporator system will recover over 93% of the water from SAGD operations for re-use in the process. More importantly, Osum will use no freshwater in the extraction process; instead using high salinity water for makeup demand for steam generation. The Silica Sorption(TM) Process used in the evaporator package was designed to tolerate the use of this brackish water as makeup that is unfit for consumption.

Flexible disposal of the evaporator concentrate from the Silica Sorption Process allows minimal treatment and safe handling of waste prior to disposal. Osum plans to use onsite disposal facilities for this concentrate in an effort to reduce truck traffic in the area.

Osum is a privately held Alberta based company focused on the application of environmentally responsible in situ recovery technologies within Canada's oil sands and carbonates.

Veolia Water Solutions & Technologies recorded revenue of $2.9 billion in 2010.

Alberta Wants more Pipelines in Addition to Keystone XL

Canada’s oil sands producers need to build at least two more pipelines the size of the controversial Keystone XL project if they are to meet their ambitious plans for growth, Alberta’s energy minister has said.

Keystone XL, a planned 1,700-mile pipeline to carry diluted bitumen, or heavy oil, from Canada to refineries on the Texas coast, has faced opposition from environmental activists over the higher carbon dioxide emissions associated with oil sands compared with other forms of oil production.

By the end of the decade, Alberta could be producing 4m to 5m barrels a day (b/d) from the oil sands and other fields – enough to put it among the world’s top 10 oil producers. But it needs more pipeline capacity to export to the US and world markets, Mr Liepert said.

“As we move forward, there will be a need for other pipelines ... By 2020, we may need three Keystones,” he said.

Such moves are likely to spark further battles with U.S. environmentalists, who want to halt development of the oil sands industry by blocking the construction of more pipeline routes out of western Canada.

The Keystone XL pipeline will be built and operated by TransCanada. More than 1,200 people – including James Hansen, a Nasa scientist, were arrested during a two-week anti-pipeline protest outside the White House in early September.

The U.S. state department, whose approval is required for international pipelines projects, said last month in its environmental impact statement on the Keystone scheme that the oil sands would be developed whether or not the pipeline was built. It concluded that Keystone XL would not in itself add to carbon emissions. It is widely expected that Hillary Clinton, the secretary of state, will approve the project by the end of the year.

Alberta’s provincial government says the state department’s thorough assessment of the plan should help to deflect criticism from other pipelines.

“It will be very, very difficult for anyone to argue that the state department did not do a thorough review,” Mr Liepert said.

Susan Casey-Lefkowitz, of the Natural Resources Defense Council, an environmental group, said the protests had raised awareness of the issue, and future projects should face even stiffer opposition.

In a sign of the expected growth of production in the region, Enbridge, a Canadian company, announced on September 12 that it was investing $1.2bn in expanding pipeline capacity in Alberta. The company also plans to connect existing underused pipelines from Canada with a new link from Chicago to Texas, called the Monarch pipeline, which could be open in 2013. Its capacity will be only about half that of Keystone’s proposed 700,000 b/d. This pipeline would not need state department approval as construction will take place only in the U.S.

Enbridge is also working on a $5.5bn Northern Gateway route west to British Columbia, from where the oil could be shipped to China. Canada’s National Energy Board will begin hearings on the project in January. Enbridge says it expects it to be in service by 2017 at the earliest.

GE SAGD Technology to Help Algar Lake Project Recycle up to 97 Percent of Produced Water

Grizzly Oil Sands ULC has selected GE’s produced water evaporation technology for its Algar Lake project near Fort McMurray, Alberta, Canada. Phase 1 of the Algar Lake Steam-Assisted Gravity Drainage (SAGD) project will produce 5,000-6,000 barrels per day of bitumen and, by using GE’s produced water evaporation process, will recycle up to 97 percent of the produced water.

“By Grizzly using GE technology at the Algar Lake SAGD project, it will help conserve the region’s freshwater supply and will greatly reduce wastewater discharge.”

Today’s announcement reinforces GE’s commitment to improve water reuse, a key commitment of ecomagination, a business strategy to create new value for customers, investors and society by solving energy, efficiency and water challenges.

Grizzly’s Algar Lake is one of three recent projects, including Harvest Black Gold, to choose GE’s patented evaporative technology to treat and recycle its SAGD wastewater, assisting this producer to minimize water consumption and comply with the Alberta Energy Resources Conservation Board (ERCB) regulations and directives pertaining to water use. Coupled with GE’s proprietary contaminant reduction system, the technology can produce a high-quality distillate suitable for use as feedwater to high-pressure drum boilers.

“Our selection of GE technology is the result of their experience and application of the technology in the oil sands,” said Ryan Chase, director of projects at Grizzly Oil Sands. “The team at GE has supported our Advanced, Relocatable, Modularized, Standardized (ARMS) design.”

As projects in Alberta’s oil sands continue to grow, so does the potential for production activities to produce large quantities of wastewater. Developers of oil sands resources are increasingly turning to GE’s evaporative and zero-liquid discharge (ZLD) technologies to address this critical issue.

Until recently, SAGD produced water could not be recycled as boiler feedwater because conventional treatment technologies were unable to produce the necessary water quality. GE’s patented evaporation process and contaminant reduction system is the only commercially proven method currently in use that achieves complete water recycling. It dramatically reduces freshwater requirements and also offers lower total capital and operating costs.

“For more than 15 years GE has been helping oil sands operators manage water resources and optimize plant performance, and our patented produced water evaporation technology is the only process capable of recycling 97 percent or more of de-oiled produced water,” said Jeff Connelly, vice president, engineered systems—water and process technologies for GE Power & Water. “By Grizzly using GE technology at the Algar Lake SAGD project, it will help conserve the region’s freshwater supply and will greatly reduce wastewater discharge.”

In addition to GE’s produced water evaporation system, GE also is providing the Algar Lake SAGD project with system design, equipment, instruments and controls, training and site support. GE will deliver equipment to the site in the first half of 2012, with installation and commissioning scheduled for the second half of 2012.

Grizzly Oil Sands was formed in early 2006 to explore for and bring bitumen into production using thermal technologies. Grizzly holds one of the largest oil sand lease positions in Alberta among independent development-stage oil sands companies with more than 700,000 net acres of oil sands leases and permits.

GE’s produced water evaporator has achieved the distinction of ecomagination-qualification. GE’s ecomagination is a corporate-wide initiative to aggressively commercialize new technologies that will help customers meet pressing environmental challenges.

Ridgeline Energy Services to Install MDL at Manitoba Hydraulic Fracturing Well Site

Ridgeline Energy Services Inc., an environmental technology and consulting company, has signed a development agreement with North American oil and gas producer to install one of Ridgeline's Mobile Development Laboratories or MDL at a hydraulic fracturing well site in the Waskada area of southwestern Manitoba.

The MDL will provide onsite real time data on a variety of treated water products. The flexibility of the MDL will allow obtaining the scientific characterization of a wide variety of treated water for reuse and recycling, the company said.

The MDL is capable of treating numerous types of contaminated water to a wide variety of treatment objectives. Ridgeline has previously tested flow back water from tight oil sources but this will be the company's first treatment system designed to treat multiple sources of water at an oil production collection facility.

Tony Ker, CEO of Ridgeline stated, "Ridgeline has established our first commercial operation in the Horn River Basin of North Eastern British Columbia. The signing of a development agreement with North American is a significant milestone in our growth strategy. Getting our first MDL into operation in the Northern BC climate was challenging and prepared us to set up and run the MDL in nearly any environment."

Interest in applying the Company's proprietary water treatment system has grown beyond the Western Canadian fracturing and produced water market. The Company has received expressions of interest from additional oil & gas markets such as: water treatment for Steam Assisted Gravity Drainage or SAGD, oil sands tailings ponds, and hydraulic fracturing operations in the US. Ridgeline has also established one of its MDL's at a waste water treatment facility in Los Angeles California to categories and treats commercial and industrial waste water.

The water treatment services will be provided by Ridgeline through the Eau Claire Partnership. The water treatment technology is licensed to the Eau Claire Partnership by DEJA II, LLC, the company added.

Oil Sands Operators Turning to Electricity to Heat and Thin Bitumen Reserves

Bruce McGee, president and chief executive of E-T Energy describing the middle point of bitumen reserves in Alberta’s oil sands says it’s “Too deep to mine and too shallow for steam”. The range, sitting between 50 and 150 meters below the earth’s surface, has mostly gone untapped by producers in the Athabasca region, but estimates put Alberta’s recoverable reserves of bitumen close to 170 billion barrels. “Mining accounts for just eight billion of it,” says McGee, “It doesn’t have a long life left, relative to in situ.”

High oil prices and new technology have allowed producers to dig deeper, using steam-assisted gravity drainage techniques to pull oil from thousands of feet underground. A typical SAGD well uses natural gas to turn water into steam in an effort to heat and thin the bitumen enough for it to flow up through a well. But, McGee turned to electrothermal dynamic stripping process (ET-DSP) technology in 2004 in the hopes of accessing what the underground extraction technique and strip mining leave behind.

His technology uses electricity to heat and thin oil reserves, as opposed to burning natural gas and using water resources. After completing trials of the technology, E-T has received a $6.86-million endorsement from Alberta’s Climate Change Emissions Management Corporation (CCEMC) and teamed up with Total E&P Canada Ltd. to help advance a 10,000-barrel-per-day development at Poplar Creek.

Although it’s only been in the past few years that SAGD projects have started to populate the oil sands landscape, in situ technology has been around much longer, going back to experiments conducted by Roger Butler at a Calgary research center run by Imperial Oil Ltd. in the 1970s. The work behind McGee’s ET-DSP has likewise evolved over time. McGee worked at Shell Canada Ltd. before pursuing a PhD in electrical engineering. His thesis, reflecting his professional experience, explored electric heating of heavy oil deposits. “I was going to work on lasers and their ability to burn out cancer cells,” he recalls. “But I was in the oil industry and it seemed like an amazing approach to extracting large amounts of bitumen.”

He drew on research conducted by professors at the University of Alberta, as well as the work of researchers at the University of California Berkeley in the Golden State’s heavy oil fields. At the time, commercial applications for the novel technology were few and far between, so McGee started a consulting firm working on environmental remediation of contaminated sites.

Not surprisingly, McMillan-McGee Corp. harnesses electric currents to get the job done. The Calgary firm has applied its specialty services to clean up spoiled industrial sites around the world. The technique passes electricity underground to safely remove chemicals from contaminated soil by burning them off or recovering them for treatment. The firm’s first consulting job, at a project in Livermore, California, attracted an unusual level of interest. “The project was written up in Scientific American and then we started getting calls from around the world,” McGee recalls.

As the firm graduated from consulting to conducting environmental cleanups at contaminated sites, McGee felt that he needed to get back into the oil and gas industry. Soaring commodity prices provided a powerful incentive to make the move, but doubts about the salability of using electric currents to recover bitumen remained. “I didn’t think we’d get far selling the technology to mining or SAGD companies. They don’t understand it and it’s not a commercial technology,” McGee says. “We figured the best way to develop it was to bid on land and it was probably the smartest thing we’ve done.” Between 2004 and 2007, E-T Energy bought up 10,560 acres in the southwest corner of the Athabasca oil sands region. The Calgary-based firm, still privately held, now holds a 100 per cent working interest in the land and estimates it has the potential to produce 1.2 billion barrels of bitumen.

At E-T’s Poplar Creek property, a series of electrode wells will be drilled approximately 16 meters apart. Electricity drawn from a nearby substation passes between the wells, heating the bitumen. Water from the formation helps move the electrical current between the wells. This water is separated from the oil and treated at the surface before being recycled through the well system, similar to radiator fluid, to help control the direction and conductivity of the electrical currents.

Once a grid of wells has reached the end of its production cycle – expected to last about a year – the entire setup is moved to another square section on site, and remediation work gets underway. The rotating process is not much different from a farmer rotating crops, McGee says. He thinks the pattern of development could accelerate reclamation of disturbed land, one of several environmental advantages proponents of electric production say give the technology a leg up on its conventional rivals.

McGee says the operation is cheaper to run than SAGD because surface facilities involved in the process are smaller. Nor does the E-T apparatus require giant trucks or shovels associated with surface mining, froth treatment equipment, boilers, high-pressure steam lines, massive separation “vessels” or tailings ponds. McGee expects the technique, which also cuts water use and shaves requirements for natural gas, will be further refined through use at Poplar Creek. “We’ll have to do multiple tests to understand the reservoir response, test different cables and connections,” he says.

The trials will be aided by Total E&P Canada. The two firms struck a “technology co-operation agreement” in April that commits the Canadian arm of the French oil major to providing financial and technical support to the project’s next two phases. The testing with Total is expected to last one year and commercial production of 10,000 barrels per day could start as early as 2013.

Interest in using electric currents to draw out hard-to-reach reserves of bitumen is growing. “The emerging use of electricity has lots of history behind it, so there are probably more companies using it than admitted,” notes Mauro Cimolai, technology advisor for Laricina Energy Ltd. “But while they’re all using electricity, they fall into slightly different camps.”

His Calgary firm, although fairly new is working hard to crack the dense Grosmont formation, where estimated reserves top 300 billion barrels. (The total is not counted in Alberta’s official reserve estimates because there is no production in the formation). Launched in 2005, Laricina has five core project developments comprising an estimated 4.6 billion barrels of recoverable bitumen. All the projects use traditional in situ production methods – except one, which uses electricity as its main energy source.

The technology, long overlooked by cost conscious companies hesitant to sink millions of dollars into field testing an uncertain bet, is getting a second look thanks mainly to high oil prices. Cimolai recalls, “With the price of oil and the price of equipment, the cost of electricity was just high enough to put this out of arm’s reach. With $100 oil or better, all of a sudden using electricity becomes more intriguing.”

Laricina has partnered with Suncor Energy Inc., Nexen Inc., and Harris Corp. to advance commercial applications of the technology through a partnership known as the Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH and pronounced “easy”) consortium. Unlike McGee’s system, the Laricina-led venture, backed by $16.5 million from Alberta’s CCEMC, is not creating a new process. Instead the companies are just tweaking current SAGD extraction methods.

The drilling will still result in two horizontal well pairs, only the ESEIEH process will see the addition of an antenna. Instead of using natural gas to heat water and force steam into the reservoir, an electromagnetic field from the antenna is sent through the bitumen and a solvent is injected to increase heating and dilution. Cimolai says electricity has been used as a power source for so long and is so well understood that it is easier to control. The same can’t be said for steam. “With steam you pump it in and it goes where it goes by brute force, but there’s not a lot of control to where steam goes,” Cimolai says.

The ESEIEH project is being touted for its environmental, as well as its operational, benefits. “If you can go to a process that eliminates steam and water to heat the reservoir, you can eliminate greenhouse gas emissions,” says Bill MacFarlane, senior research and development advisor with Nexen. He says the project will also test the economics of the process. “How much infrastructure do you need? How much are energy costs? How fast does the temperature rise? What’s the distance from the well bore? We need metrics to go into a full-scale demonstration to show it is cost [effective].”

Harris Corp. brings more than 50 years of electromagnetic experience to the partnership, including contracts designing networks and radar systems for the U.S. Department of Defense. “The future of the industry in research and development will rapidly develop, not through academia, but through partnerships like this.” MacFarlane says.

With the ESEIEH project launching just last year, it’s not expected to wrap up until 2014. Commercial use could still be 10 years away, but Cimolai is eager for that day to arrive. “The benefits are strong enough where people will drop the old techniques and will pick up this technology,” he says. “It will be like moving from the cart and horse to the automobile if we get it right.”

Grizzly Oil Sands Awards $4 Mln Algar Lake Order to Rockwell Automation

Grizzly Oil Sands, based in Alberta, Canada, has awarded a contract work over $4m with Rockwell Automation, to supply its PlantPAX process automation system for Grizzly Oil's Algar Lake project.

The project produces over 5,000 barrels of oil per day, using steam assisted gravity drainage (SAGD).

Grizzly Oil says it needs an advanced control system to help run the special facilities model it has developed, called "Advanced Relocatable Modular Standard development."

'For our unique Grizzly facility model we needed an advanced, integrated process and motor control system that would monitor multiple SAGD sites from one central location, now and as we expand," says Brian Harrison, vice president, Engineering, Grizzly Oil Sands.

Grizzly will build a shadow (copy) control room at its Calgary headquarters to monitor and control all oil sites across Northern Alberta.

Rockwell's "unique, open architecture is an important reason Rockwell Automation won the order,' he said.

The project also includes project management and engineering services, low- and medium-voltage motor control centers, and a PowerFlex 7000 medium-voltage variable frequency drive.

Ceramic Sand Mix Boosts Bakken Hydraulic Fracturing Expenses

A big difference in well expenses around North Dakota's shale is largely due to variable costs of a key ingredient in the hydraulic fracturing process, the chief executive of Kodiak Oil & Gas said on September 26.

Sand is a common "proponent" used to keep fractures in shale rock open after a frac job is complete. But a pricier ceramic substitute, such as that made by Carbo Ceramics, is used in its place to varying degrees, depending on either the nature of the well or the availability of sand, Reuters reported.

Executives say getting their hands on sand in North Dakota's remote Bakken shale region can be hard, while a wider U.S. fracking boom in some cases has led to shortages of the sand that cannot be easily resolved.

Kodiak Chief Executive Lynn Peterson said much of the difference between his company's $9.5 million per-well cost in North Dakota and the $6 million of Whiting Petroleum had to do with Whiting's greater use of sand.

Peterson also said trucking costs in North Dakota contributed to inflation in the oil-rich region, which saw a surge in activity as crude oil jumped to as high as $100 per barrel.

"Some of these costs, quite frankly, have gotten out of control," he told investors at a conference hosted by the Independent Petroleum Association of America.

Peterson said the problem with trucking costs would be solved once more infrastructure was built in the area, which he believed could not handle many more trucks.

As for the ceramics mix, Abraxas Petroleum chief executive Robert Watson said he aimed to use an average of 40% ceramics on Bakken wells. But on a recent well, Abraxas was forced to inject 60% ceramics because flooding in the region had prevented a shipment of sand from arriving.

Whiting believes it is the largest customer in the region for Halliburton’s white sand, since it has their crews committed to its wells, Whiting Chief Executive James Volker told Reuters on the sidelines of the IPAA conference in San Francisco.

At $6 million per well and $80-per-barrel oil, he told investors that Whiting could expect at least a 3-to-1 return.

GAIL India Acquires Stake in Carrizo's Eagle Ford Shale Gas Assets for $95 Mln

GAIL (India) Ltd. said September 29 its U.S. unit has acquired a 20% stake in Houston-based Carrizo Oil & Gas Inc.'s Eagle Shale Ford acreage for $95 million.

The Indian gas transmission company will invest around $300 million over five years, including an upfront cash payment of $63.7 million and a carry amount of $31.3 million linked to Carrizo's future drilling and development costs, GAIL said in a statement.

GAIL's U.S. unit, GAIL Global, would fund a major part of the investments out of its earnings, it said.

Bullish Projections Released on Impact of Utica Shale

The Ohio Oil and Gas Energy Education Program (OOGEEP) released a very bullish projection in September on the economic impact of Utica shale activity in the region.

The report predicted that Utica shale production could generate 204,500 jobs in just four years and infuse billions into the regional economy.

It follows claims by Chesapeake Energy that the Utica is “analogous” to the Eagle Ford. It also claimed that its holdings in the region could generate up to $20 billion for shareholders – greater than its entire current market cap.

“The play reminded us of the Eagle Ford shale, which is distinctive because it’s a three-phase play of dry gas, wet gas and liquids,” Chesapeake CEO Aubrey McClendon said.

David Fessler recently explained the importance of the liquids-rich shale plays right now, and eastern Ohio is certainly shaping up to fit that bill.

Chesapeake Energy isn’t the only company bullish on the prospects of the Utica. EV Energy Partners (EVEP) Chairman and CEO John Walker feels the presence of more than just shale will attract petroleum companies and help bring business to oil refineries in the region owned by Marathon Petroleum Corp. (MPC).

“We hope to drown the Marathon refineries in Ohio [with Utica oil],” Walker said.

Chesapeake, which holds the lion’s share of acreage around Utica, is also said to be looking for a foreign partner to bring in for exportation and de-risking purposes.

In the past, Chesapeake Energy has worked on similar ventures with Statoil, BHP Billiton plc and CNOOC Ltd., among others.

Chevron recently acquired Atlas Energy and ExxonMobil) recently acquired XTO Energy, giving the two giants exposure to Utica.

Hess, CONSOL Energy and PDC Energy are also active in the region, along with Devon Energy and Anadarko Petroleum.

As the prospect at the Utica becomes clearer, some other smaller companies with exposure, similar to XTO and Atlas, may become attractive M&A targets to larger companies.

Prime takeover targets may include:

Rex Energy Corp., which holds acreage in the Utica with a market cap around $645 million.
Another would be Magnum Hunter Resources, with a $530-million market cap.
Gulfport Energy Corporation is more than double the size of Magnum Hunter and Rex at $1.35 billion, but also operates at a profit, unlike those other two.

And steel companies around eastern Ohio, such as AK Steel Holding Corporation Co. and Timken Company, could benefit from the increased drilling activity in the region.

According to Rigzone, “Steel remains an important industry in Ohio, and the anticipated boom in the Utica shale drilling has led to commitments from steel companies in Ohio to expand facilities for manufacturing oil and gas equipment.”

While the Utica could certainly turn out to live up to the expectations being pumped up by McClendon and the OOGEEP, it’s still early in the game. There are only 16 wells, and we still don’t know much about shale drilling and its long-term effects on the environment.

In the more populated Northeastern United States, it may face more public opposition than in more rural parts of the country, such as the Bakken and Eagle Ford, and even the Marcellus shale plays.

Shell Oil Cracker Plant Eyed by Ohio for Utica Shale

Shell’s’s plans to build a multibillion-dollar ethylene cracker plant to process natural gas liquids from the Marcellus and Utica shale formations and it has the attention of Ohio’s David Mustine, general manager for energy projects at Jobs Ohio, the state’s new economic development entity

Mustine is trying to keep Ohio in the game for a Shell plant that is being hotly pursued by Pennsylvania and West Virginia as well. Shell, which reported in June that it plans to build the facility in the Appalachian region, said it would make a decision on the location this year.

Anadarko Obtains Drilling Permits For Well In Utica Shale

Anadarko Petroleum Corp. has obtained permits to drill a well in the Utica Shale formation in eastern Ohio, according to the state's oil and gas regulator. The move makes the Houston company the latest energy firm to enter this big North American oil discovery.

Anadarko obtained permits this month to drill a horizontal well in Guernsey County targeting the Utica Shale, according to the Ohio Department of Natural Resources. Sparsely populated Guernsey County is located about 90 miles east of Columbus.

While Anadarko has been quieter about its activities in Ohio than some of its competitors, which include Hess Corp., Devon Energy Corp. and Chesapeake Energy Corp., the drilling permits show the Houston explorer has gained a foothold in the state. The size of Anadarko's position in the Utica Shale was not included in the information made public by the Ohio regulator.

Recently, Hess said it spent more than $1.34 billion acquiring 185,000 acres in Ohio. The New York company spent $593 million on a 50% interest in 200,000 acres held by Consol Energy Inc. (CNX) and spent another $750 million acquiring closely held Marquette Exploration LLC, which had 85,000 acres in the shale.

Enterprise, Enbridge, Anadarko Plan 580 Mile Texas NGL Pipeline

Enterprise Products Partners L.P., Enbridge Energy Partners, L.P., and Anadarko Petroleum Corporation on September 6 announced an agreement to design and construct a new natural gas liquids (NGL) pipeline that will originate from Skellytown, Texas in Carson County and extend approximately 580 miles to NGL fractionation and storage facilities in Mont Belvieu, Texas.

The new Texas Express Pipeline ("TEP") will help producers in West and Central Texas, the Rocky Mountains, Southern Oklahoma and the Mid-continent maximize the value of their natural gas production by providing additional takeaway capacity and enhanced access to the Gulf Coast NGL market. Initial capacity on TEP will be approximately 280,000 barrels per day (BPD), which can be readily expanded to approximately 400,000 BPD.

In addition, the joint venture will include two new NGL gathering systems. The first will connect TEP to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and Western Oklahoma. The second NGL gathering system will connect the new pipeline to Central Texas, Barnett Shale processing plants. Volumes from the Rockies, Permian Basin and Mid-continent regions will be delivered to the TEP system utilizing Enterprise's existing Mid-America Pipeline ("MAPL") assets between the Conway hub and Enterprise's Hobbs NGL fractionation facility in Gaines County, Texas. Enterprise will construct and serve as the operator of the pipeline, while Enbridge will build and operate the new gathering systems. The pipeline and gathering systems are expected to begin service in the second quarter of 2013, subject to regulatory approvals.

"We are very pleased to partner with Enbridge and Anadarko on this project, which offers a comprehensive industry solution for addressing NGL transportation constraints that are currently limiting access to the largest domestic NGL market located along the Gulf Coast," said Michael A. Creel, Enterprise president and chief executive officer. "The new pipeline and gathering systems, which are underpinned by long-term contracts, will also have the capability to provide takeaway capacity for other producing areas not presently served by the MAPL system, including Oklahoma's Granite Wash, the Anadarko-Woodford basin, and the Barnett Shale. Wider access to multiple production areas, in addition to a competitive transportation fee structure, makes this an attractive option for producers and natural gas processors. NGLs controlled by affiliates of Enterprise, Enbridge and Anadarko will solidly anchor the project."

"Enbridge is also very pleased to be working with Enterprise and Anadarko on this critical NGL pipeline," said Mark Maki, president of Enbridge Energy Partners, L.P. "Through our extensive gathering and processing assets, Enbridge has developed a significant and growing NGL supply position in Texas and Oklahoma. The Texas Express Pipeline will provide guaranteed NGL access to the primary U.S. petrochemical market in Mont Belvieu, ensuring premium NGL netbacks for our customers. Importantly, the Texas Express pipeline fulfills a key strategic objective of Enbridge to extend our value chain from gathering and processing to include NGL transportation, providing Enbridge's unit holders with a new source of strong and stable cash flow."

Anadarko Vice President, Midstream, Danny Rea, said, "This project will further enhance our ability to consistently access premium Mont Belvieu markets and increase the wellhead netbacks for our growing NGL production from our Rockies and Texas assets, as well as better align our interests with the project developers through our equity participation."

While providing producers with much-needed takeaway capacity, TEP will also supply petrochemical facilities with a reliable, domestic source of feedstock. Demand for natural gas-derived feedstocks remains strong, driven by the wide spread between crude oil and natural gas prices.

U.S. / ROMANIA / RUSSIA

Russia’s TMK May Spend $3 Bln on Pipe Production in U.S., Romania and Russia

OAO TMK, the world’s largest maker of oil and gas pipes by output, may spend as much as $3 billion this decade on projects in Russia, Romania and the U.S. as rising profit drives technology upgrades and growth.

“We’ve spent about $2.5 billion on modernization so far and about $2 billion more on acquiring new assets to expand the business,” billionaire owner Dmitry Pumpyansky said in an interview. TMK plans to invest about $300 million a year by 2020 to maintain those assets and develop new pipe products, he said.

The new spending proposal coincides with the completion of TMK’s $2.5 billion investment program, begun six years ago, and follows a fourfold jump in first-half profit. TMK and European competitors including France’s Vallourec SA are investing in more-advanced products as oil and gas companies explore in remoter and deeper fields to counter declining output elsewhere.

TMK must keep spending to remain the “industry leader,” boost earnings and increase its market value, while expanding into “advanced-quality” pipes, Pumpyansky said in Moscow on September 22. The company, which has plants in Russia, Romania, Kazakhstan and North America, will spend 25 percent to 30 percent of annual investment in the U.S., he said.

The Moscow-based pipemaker bought 10 U.S. factories previously held by Ipsco Inc. in 2008 for $1.2 billion. TMK Ipsco is now the U.S.’s No. 3 pipe producer, and counts Exxon Mobil Corp. and Royal Dutch Shell Plc among its clients, Pumpyansky said. TMK Ipsco got a $260 million credit line from Wells Fargo & Co. this year.

The move “opened the door to cheap American financing,” the billionaire said, adding that U.S. interest rates are 200 to 300 basis points lower than in Russia. TMK will “seriously expand” in North America and invest in producing “premium connection” pipes and tubes for offshore drilling, he said.

A shift into the offshore drilling market would pit TMK against Vallourec and Luxembourg-based Tenaris SA, according to Olga Danilenko, a Moscow-based analyst at VTB Capital.

“Only Tenaris and Vallourec are able to supply pipes for offshore oil and gas drilling so far,” Danilenko said September 23. “If TMK succeed in it, it will be a sort of revolution.”

Premium-connection seamless pipes command higher prices because they enable oil and gas producers to drill deep and at pressure, Danilenko said, adding that the U.S. market is particularly lucrative. Even ordinary seamless pipes sell for 25 percent more in the U.S. than in Russia, she said.

Pipe demand isn’t suffering from the global market turmoil, according to Pumpyansky, who said financial market instability “isn’t based on fundamentals” and demand in Russia has gained 30 percent this year. In the U.S., active oil rigs totaled a record 1,886 as of July 1, Baker Hughes Inc.’s Rig Count shows.

“We conservatively expect the U.S. market to increase by 5 to 10 percent next year,” Pumpyansky said. Pipe stockpiles in the country will last only five months, compared with as long as 10 months in 2008, before the economic crisis sapped production, he said.

Goldman Sachs Group Inc. said in April that gas consumption in the U.S. may surge by as much as 20 billion cubic feet a day in the next 20 years because of demand from the power generation and transport industries. The U.S. has become the world’s largest gas producer, largely as a result of a boom in shale gas development, whose extraction methods have sparked concern among groups including the Environmental Protection Agency.

“We don’t see any real intention of the U.S. government to ban shale gas drilling, which could have an effect on us,” Pumpyansky said, adding that high-quality pipes can remove the risk of environmental pollution from shale extraction, which uses water, sand and chemicals to fracture gas-trapping rocks.

TMK expects to raise the share of its U.S. and other foreign units in total sales. While Russia currently accounts for 60 percent of revenue, TMK is seeking to get about half from overseas assets in the “near future,” Pumpyansky said.

The company reported a fourfold increase in first-half net income on Sept. 2, beating analyst estimates, and confirmed previous guidance on growth in sales volumes.

Full-year earnings before interest, tax, depreciation and amortization will exceed levels in 2007 to 2008, Pumpyansky said, adding that TMK’s Ebitda margin is closing the gap on Vallourec. Ebitda reached $996 million in 2008, and analysts expect 2011 earnings of $1.2 billion, according to the average of 15 estimates compiled by Bloomberg.

TMK hopes to increase dividend payments and won’t need to sell shares to pay down debt, Pumpyansky said. Debt was $3.84 billion at the end of March, which implies a ratio of net debt to Ebitda of 3.3. TMK targets a ratio of 1.5 to 2, he said.

“The average interest rate we pay on our debt now is 7.33 percent, and we plan to improve our debt profile further.”

CANADA

Suncor Awards Jacobs Firebag Contract for Fort McMurray Stage Three In-situ Oil Sands Project

Jacobs Engineering Group Inc. announced on September 6 that it has been awarded a contract by Suncor Energy to provide support for a program of sustaining works as part of its Firebag Stage Three in-situ oil sands project near Fort McMurray, Canada.

Officials did not disclose the contract value.

Jacobs has completed the detailed design phase of Firebag Stage Three; providing support for sustaining projects is the next step in Jacobs' involvement with the Firebag program, as Jacobs is currently involved in managing the ongoing pre-sustaining projects. By capitalizing on technical experience and continuously improving standards and processes, Jacobs works to facilitate operational effectiveness, reduce costs and maintain a strong safety record.

In making the announcement, Jacobs Group Vice President Chip Mitchell stated, "Transitioning from delivering capital projects to sustaining projects is a natural shift for Jacobs, leveraging our relationship-based model to continue delivering increasing value on an ongoing basis. We are delighted to continue to support Suncor’s operations at its Firebag oil sands project."

Mariner West Open Season Successful for Sunoco Logistics

Sunoco Logistics Partners L.P. announced on September 7 that it had a successful open season for Project Mariner West. Sunoco Logistics received binding commitments that enable the project to proceed as designed with an initial capacity to transport approximately 50,000 barrels per day and the ability to expand to support higher volumes as needed.

Saipem to Build Secondary Horizon Oil Sands Upgrader

Saipem has been awarded a new EPC Lump Sum contract by Canadian Natural Resources Ltd. The project consists of the engineering, procurement and construction of a Secondary Upgrader with a production capacity of 42,599 BPSD (barrels per stream day) of Hydrotreated Gas Oil, as part of the Horizon Oil Sands Project—Hydrotreater Phase 2—in Alberta, in the Athabasca region, Canada.

The scope of the project includes three units, to be built within the existing complex: Gas Oil Hydrotreating Unit (GOHTU), Common facilities (Substation & Rib), Wash Water and Rich Amine System and the Interconnecting Piperack.

The complete Horizon Oil Sands Project will develop oil sands resources on Canadian Natural Oil Sands Lease, about 70 kilometers north of Fort McMurray in a phased development. At full capacity, the project will produce 250,000 B/cd of synthetic crude oil, from 270,000 B/cd of mined bitumen.

The EDS (Engineering and Design Specification) package for the plant is entirely prepared by assembling documentation from the current design of the plant constructed by Saipem on 2008, for the same client.

The project will be completed in 44 months.

Babcock & Wilcox Canada to Supply Four Modular Boilers for Kearl Project

The Babcock & Wilcox Company announced September 21 that its subsidiary Babcock & Wilcox Canada Ltd. (B&W Canada) has been awarded a contract to supply four modularized boilers for the Kearl Oil Sands Project being developed by Imperial Oil in the Athabasca Oil Sands Region, north of Fort McMurray, Alberta, Canada.

B&W Canada supplied the first four TSSG boilers for the initial scope of the project and will supply an additional four TSSG boilers for expanded capacity. The boilers will produce utility steam that will be used to support various processes in the plant.

B&W's TSSG is a bottom-supported boiler and features a unique modularized design that maximizes shop assembly and provides customers greater certainty with respect to delivery and overall project schedule.

Selected components, such as headers and wall panels, will be fabricated in B&W Canada's Cambridge facility, while component fabrication and modularization will be completed in B&W Canada's Melville, Saskatchewan facility.

Completed pressure part modules are expected to be shipped directly to the Kearl site from B&W's Melville facility in 2013.

India’s Reliance Eyeing Canadian Shale Gas Assets

Mukesh Ambani led Reliance Industries Limited (RIL) is eyeing shale gas assets in the resource-rich regions of Canada, after having successfully acquired and developed similar shale gas assets in Pennsylvania and Texas in the U.S. last year. Encana Corp. (Canada’s biggest natural-gas producer) and Cenovus Energy Inc (Canada’s fifth-largest energy company) are two Canadian companies looking for partners to successfully develop their oil and gas resources. Both these companies, at present, are in talks with leading Asian and European energy companies to put together a mutually beneficial partnership for developing Canada’s rich shale gas reserves. RIL, one of the top prospects, is presently studying Canadian shale gas assets and evaluating the possibility of likely partnership with its energy firms.

Reliance Industries has inked joint ventures with U.S. based Chevron (RIL- Chevron), Carrizo (RIL- Carrizo) and Pioneer (RIL-Pioneer). Acquisition of shale gas assets has been a significant venture for RIL this fiscal year, and in hopes of transforming itself into a global oil and gas developing enterprise in the coming years, Reliance is on the lookout for additional global opportunities and for extending a hand of partnership to leading oil and gas developing firms of the world. By adding reserves of natural gas trapped in overseas shale gas assets, Reliance will be able to add to its domestic fuel output substantially.

After having encountered the highest ever financial performance results for the quarter ending June 30th, earnings from RIL’s refining business helped the conglomerate assume a 16.7% rise in net profits and $16 billion in cash reserves. RIL is expected to invest a part of this cash reserves into developing additional clean energy ventures. Also, Reliance has been India’s most acquisitive company in terms of number of deals last year, and the company is expected to expand further by engaging in additional M&A opportunities. RIL has roped in NavinWadhwani from Rothschild to head the M&A division of the group and the company also plans to bring in Tony Fountain, ex-CEO of the U.K. Nuclear Decommissioning Authority to head its refining and marketing division.

CANADA / U.S.

Feds Casting Doubts over Accident Risks on Keystone XL Pipeline Expansion

Federal bureaucrats are casting doubts on claims that a controversial oilsands pipeline expansion in the United States would be prone to accidents because of the corrosive nature of crude oil derived from Alberta's bitumen deposits, according to internal government briefing notes.

The possibility of pipeline leaks caused by the crude oil from the region, commonly referred to as the tarsands, was raised in February by several American environmental and advocacy groups led by the Natural Resources Defense Council.

The concerns were dismissed at the time by the Alberta government as well as TransCanada, which is proposing the multi-billion dollar Keystone XL pipeline expansion that would link the oilsands to the Gulf Coast of Texas.

An assessment of the environmental groups' report by Natural Resources Canada, released to Postmedia News through access to information legislation, has also defended the safety of the project while acknowledging the damaging nature of the warnings on public opinion.

"This is a new area of research for everyone," said a briefing note drafted by Bruce Akins, a senior adviser on oil and gas regulations issues at Natural Resources Canada. "Further, (a government scientific research unit) suggests that with proper care and treatment, a pipeline carrying more corrosive products should be able to last as long as one carrying less corrosive products."

Akins also warned that the NRDC report could influence the project's fate as well as another pipeline project, proposed by Enbridge, that would link the oilsands with the British Columbia coast.

"However, once posted on the Internet, an (environmental group's) report tends to have its own life, and will be cited repeatedly, regardless of whether some or all of its assertions have been debunked, or responded to," said the briefing note. "What will be most important is whether this report, and its recommendation to not certificate the Keystone XL pipeline in the U.S. until further safety research has taken place and regulations passed (which would take years), is taken seriously by the U.S. administration."

A scientist at the department's research lab, CanmetENERGY, who is studying the corrosive properties of different petroleum products, explained in an interview that the high Total Acid Number of bitumen crude oil would not cause corrosion at temperatures under 200 C.

"Since the pipeline is running at much lower temperature, say 55 degrees centigrade, this is not going to have any impact on it," said Heather Dettman, a bio-processing senior scientist who is based in Alberta. "The TAN can impact in the refineries, but you have to be above (temperatures of) 200 degrees Celsius."

She said water could also cause corrosion, but noted this also applies to other forms of oil if the pipeline is not adequately built.

The assurances from the Canadian government were immediately rejected by Richard Kuprewicz, an engineer who advises a U.S. government safety panel on pipelines. Kuprewicz said that weaker existing regulations in the U.S., compared to Canada, could allow for corrosion, even at temperatures under 100 C.

"I don't want to embarrass anybody, but they have no idea what they're talking about," said Kuprewicz, who runs a pipeline consulting firm, Accufacts Inc., which has also done contracts for energy companies such as TransCanada. "This line will have water in it, just by the nature of the beast."

But he stressed that the company could address concerns promptly if it was willing to work with environmental groups.

"These aren't deal killers but you've got to address them right up front," said Kuprewicz. "If the parties were to get in a room and act as adults and clearly address their concerns, and rather than be in denial and try to fight, the parties could say, we could address these issues by (working together)."

Recent protests against the Keystone expansion project that have provoked hundreds of arrests in the U.S. have been indirectly aimed at growth of the oilsands industry which requires higher amounts of water, energy and land use when compared with conventional oil production. Recent statistics from Environment Canada have revealed that the oilsands industry now contributes to global warming more than all of the cars on Canadian roads and that it is projected to continue exponential growth that could cancel out efforts of other Canadian industries to reduce their carbon footprint and meet targets set by Prime Minister Stephen Harper under the Copenhagen climate change agreement.

Policy analysts at the Natural Resources Defense Council said the existing evidence from the records of pipeline companies indicate that the U.S. government and scientists have not done enough research to analyze the risks.

"What we're calling for is additional study," said Anthony Swift from NRDC international program. "We're seeing new pipelines devoted to the movement of this particular substance and the fact that we're moving forward on these projects with no due diligence is highly disturbing."

ASIA

CHINA

PetroChina to Commence Commercial Shale Production By 2015

PetroChina is looking to tap into the shale deposits in southwest China's Sichuan basin and is anticipating production of 1 billion cubic metres of shale gas in 2015. Changning, Weiyuan and Fushun-Yongchuan blocks in Sichuan together comprise the acreage which the company is eyeing as potential shale gas plays. According to Li Luguang, head of PetroChina's Sichuan subsidiary, Fushun-Yongchuan is being jointly evaluated in partnership with Shell.

China's natural gas consumption last year was 100 billion cubic meters, which is expected to triple in the next ten years. Exploration of unconventional resources like shale is steadily catching speed as a viable option to offset growing dependency on conventional fuels. However, shale gas production in China hasn't taken off commercially yet.

According to Reuters, other energy firms vying for a position in China's emerging shale market include Shaanxi Yanchang Petroleum Group that is targeting 500 million cubic meters by 2015 and has revealed that Ordos Basin where it operates is believed to be holding 15 to 18 trillion cubic meters of shale gas.

Other giant contenders include Sinopec Corp which is in the process of appraisal and is aiming to reveal its production forecast in 2015.

EUROPE

POLAND

Poland’s Baltic Shale Gas Evaluation Moving Ahead

3Legs Resources PLC completed tests at two shale gas wells, one of which encountered a new shale interval, in Poland’s Baltic basin while Talisman Energy Poland has spudded its first well.

3Legs said the Lebien LE-2H well flowed gas on nitrogen lift at an unstable rate declining from 2.2 MMscfd on September 8 to 500 Mscfd on September 13. The company ran tubing and the well continued to flow on nitrogen lift to recover frac water with gas increasing from an initial 380 Mscfd to 450-520 Mscfd on September 25, when 15% of the frac water had been recovered, before being shut-in for further analysis.

Interpretation of the logs, run after the multistage fracs indicates that the frac propagated to a portion of the reservoir in each of the 13 stages but, not to all of the reservoir. The company plans to review frac designs with the intention of improving frac performance on future wells.

The well achieved its two key objectives of attaining a sustained gas production rate and providing critical data for drilling and stimulation design for future wells.

The 3Legs Warblino LE-1H well, 25 km west of Lebien LE-2H, went to a total depth of 3,222 m and encountered a separate deeper interval in addition to the intervals completed at Lebien LE-1 and Lebien LE-2H.

Warblino was sidetracked to drill a horizontal borehole in the deeper interval. After drilling a 1,246-m horizontal lateral of shale with strong gas shows, and just prior to reaching planned total depth, the well encountered hole stability issues and a sidetrack was kicked off to redrill the same section.

The new lateral was drilled to 3,844 m measured depth with a 500-m horizontal section, shorter than originally planned, so as to reduce the risk of encountering hole problems. A stimulation program is pending.

Meanwhile, Talisman has spudded the Lewino-1G2 well on the Gdansk-W concession, said partner San Leon Energy PLC. The Lewino well targets unconventional shale gas in the Lower Silurian, Ordovician, and Upper Cambrian and is the first of a three-well program. The other two wells will be on the Braniewo and Szczawno concessions.

Polish Shale Gas could be Commercialized Starting in 2014

The commercial production of Polish shale gas may begin as soon as 2014, said Polish Prime Minister Donald Tusk.

"With moderate optimism we think that in 2014 there will be commercial extraction, so it's really just around the corner," Mr Tusk told reporters while visiting Polish gas monopolist PGNiG's shale gas concession in Lubocino, northern Poland.

The prime minister added that Poland may be able to rely on its own gas resources by 2035. At present Poland is dependent on imported gas, sourced mainly from Russia.

"After years of dependence on our large neighbor, today we can say that my generation will see the day when we will be self-reliant when it comes to gas," Mr Tusk said.

Aware of the heavy criticism shale gas extraction has come under from some environmentalists and scientists, Mr Tusk said that exploitation of shale gas deposits will not endanger the environment. He added that the extraction of shale gas is a strategic challenge for Poland and should not be influenced by the interests of a “foreign lobby.”

Earlier this year French deputies banned hydraulic fracturing, a controversial process used to extract shale gas. There are now fears that the European Union could create regulations that would make it difficult for Poland to develop its shale gas industry.

The prime minister also said that his aides, in cooperation with Norwegian and Canadian experts, are preparing the relevant legal provisions to ensure that Poland can profit from shale gas extraction. The proposed scheme envisions the introduction of fees for extraction companies that would be used to shore up Poland's pension system.

Poland's shale gas reserves are estimated at 5.3 trillion cubic meters and could make the country independent from Russian gas for hundreds of years, and even enable Poland to become a net exporter.

Poland's Shale Gas Becomes a Dilemma for Europe

Despite environmental fears, gas finds offer some countries a chance to slash energy costs and lessen dependence on Russia.

In early September, Prime Minister of Russia, Vladimir Putin, and former German Chancellor, Gerhard Schröder, ushered in what was widely seen – for better and worse – as a new era in the European gas market. On September 6, at a ceremony outside St Petersburg, the Nord Stream pipeline that takes natural gas directly from Russia to Germany under the Baltic Sea was inaugurated.

Bypassing Ukraine, Poland and the Baltic States, the new pipeline is also designed to bypass the disputes that have periodically halted the flow of Russian gas to the rest of Europe.

Even as the new gas started to flow, however, there were the first signs that the European gas market could be in for even more radical reshaping within less than 10 years.

At an economic forum in Poland which happened to coincide with the opening of Nord Stream, the main topic – was of the potential for shale gas, a resource that has quietly altered the balance of energy provision in the United States and helped bring prices there down by a fifth in the past five years.

Initial surveys indicate Poland has enormous reserves of shale gas. One from the U.S. Department of Energy suggests Poland could have as much as 5.3 trillion cubic meters – equivalent to 300 years' domestic consumption.

But drilling for shale gas is controversial, especially among environmentalists. Although the technique – which involves extracting the gas by blasting the shale rock layers with high pressure sand, water and chemicals – has been known for a century, it is only in the past decade that it has become economically and technologically viable. But many fear that such "fracking" causes subsidence and contaminates ground water, and it has been banned in France, Switzerland and some U.S. states. The recent discovery of shale gas deposits near Blackpool has also prompted calls for a UK ban.

The Green movement also fears that new, and exploitable, supplies of gas could reduce prices to the point where investment in alternative energy sources, such as wind and wave power does not make economic sense.

In Poland, however, the exploitation of shale gas is well on the way to becoming something of a national mission. Poland's Prime Minister, Donald Tusk, has described shale gas as his country's "great chance" to turn Poland from an energy importer to a major exporter within a generation. And the subtext for Warsaw is that shale gas could not only make Poland into an exporter, but also end its age-old energy dependence on Russia.

With a general election on October 9, Mr Tusk's ruling party is already capitalizing politically on the issue and has published a four-year program, which promises, among other things, the creation of a special fund for the proceeds from shale gas, to be used to pay future pensions. It may not be coincidence that this month the Polish energy conglomerate, PGNiG, torched the first flare on one of its rigs at Lubocino in the north of the country. Commercial shale gas production is projected to start in 2014. Because his is one of the few governments in Europe to escape the effects of the financial crisis, Mr Tusk's government is confidently expected to be re-elected.

Not everyone, though, shares Poland's enthusiasm for shale gas. For obvious reasons, some of the fiercest critics are to be found in Russia, which cannily cast itself among the eco-warriors at the economic forum in Poland, playing down the economic repercussions.

Poland and Russia have had a difficult relationship albeit one that has recently undergone a modest improvement. But a Poland that became self-sufficient in gas would take quite a bite out of Russia's exports. And if Poland became a net exporter, other markets – Ukraine, the Baltic States and others – could also be lost to Russia. The entire business model of Russia's mega-conglomerate, Gazprom, would be called into question.

To an extent this is already happening. The European gas market has been changing, and not in Russia's favor. When Ukraine stopped the flow of Russian gas westward in the winter of 2009, a combination of existing European contingency plans and emergency cobbling-together soon replaced almost 90 percent of the gas that would have come from Russia. This showed both Russia and Ukraine that their leverage was not what it once was.

There is also more gas on the market. Britain, where the Russia-Ukraine crisis served to highlight the dearth of gas storage, now has a state-of-the art terminal for liquefied natural gas at Milford Haven. And reduced demand for imported gas in the U.S., thanks to the development of shale gas there, has increased stocks of LNG for delivery elsewhere. Even if Europe is not experiencing an actual gas glut, it is no longer threatened by a shortage.

The opening of Nord Stream adds a further dimension. With the potential to increase reliability of supplies and keep prices down, it can be seen as enhancing Europe's, and more particularly Germany's, energy security. This is why Berlin has always been enthusiastic about it. But it can also be seen as part of Russia's post-Soviet energy strategy – which is why Poland and Ukraine, as transit countries, have been so hostile to it. They feared being left – literally and figuratively – out of the loop, with no transit fees and no leverage. Shale gas comes, for Poland, as a form of salvation.

Whatever reassurance the opening of Nord Stream offers Russia, the prospect of competition from Polish gas within Central and Eastern Europe can hardly be welcome either to Gazprom as a company or to Russia. And as Poland dreams of untold wealth and power from gas exports, Russia faces a bad combination of lower prices and fewer customers.

So far, Poland's shale gas is 10 per cent gas and 90 per cent politics. Even if its reserves are as high as hoped, that balance will not necessarily change. But the politics and configuration of Europe's gas market will be unrecognizable from today.

ExxonMobil to Start Second Shale Gas Test Well in Poland

ExxonMobil planed to start hydraulic fracturing in early October on its second test well in Poland, near the eastern town of Siennica, Jim Johnston, board member of ExxonMobil Exploration and Production Poland, said September 28.

Outside the U.S., Poland is one of the first countries where companies are seriously attempting to develop shale gas--a development the Polish Prime Minister Donald Tusk has called the country's "great chance," because it could reduce Poland's dependence on Russian gas, create tens of thousands of jobs and fill state coffers.

ExxonMobil has six licenses to explore for shale gas in Poland.

In the Lublin Basin, Exxon is operating in partnership with French oil major Total, which holds a 49% stake in the licenses.

In the Podlasie Basin, Exxon has partnered with Hutton Energy.

Johnson was speaking in Krakow at a conference on Europe's unconventional gas sector.

UKRAINE

Ukraine May Sign $1Bln in Shale Gas Contracts with Western Firms

Ukraine may sign gas production contracts worth a total of $1 billion with ExxonMobil, Halliburton, Eni and Total this month, Kommersant Ukraina business daily said on September 23.

ExxonMobil wants to produce shale gas, while Eni and Total are interested in deposits which are hard to explore, a Ukrainian Energy and Coal Production Ministry source told the paper. This month the Ukrainian authorities signed an $800 million contract with Royal Dutch Shell for geological exploration and production of shale gas in the east of the country.

"We hope that the agreement will allow us to triple domestic gas output in two to three years," the source told Kommersant Ukraina.

Ukraine, unhappy with its dependence on Russian gas, is seeking alternative energy sources, including shale gas. Experts say that the signing of the agreements with western companies is a way to pressure Russia into revising gas contracts ahead of September talks between Ukrainian President Viktor Yanukovich and the Russian authorities.

Ukraine is seeking to review gas deals with Russia, saying its 2009 contract's gas price formula is unfair. Moscow has tied the price for gas to the international spot price for oil, which have risen strongly since that year due to the instability in the Middle East. Ukrainian Prime Minister Mykola Azarov has said Ukraine was ready for compromise.

Ukraine's internal gas production stands at about 20 billion cubic meters. It imported 40 bcm from Russia last year. Industry analysts say that Ukraine holds Europe's largest reserves of shale gas and can produce 7 to 10 bcm a year of it.

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